via electronic filing and huddle · page 2 of 4 riley g peck davison van cleve, pc 333 sw taylor,...

August 22, 2017 VIA ELECTRONIC FILING AND HUDDLE Public Utility Commission of Oregon 201 High Street SE, Suite 100 Salem, OR 97301-3398 Attn: Filing Center Re: UM 1802 – PacifiCorp Reply Testimony and Exhibit PacifiCorp d/b/a Pacific Power hereby submits for filing the Reply Testimony and Exhibit of Daniel MacNeil. Electronic workpapers will be posted to Huddle. Please direct any informal correspondence and questions regarding this filing to Natasha Siores Manager, Regulatory Affairs, at (503) 813-6583. Sincerely, Etta Lockey Vice President, Regulation Enclosures

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CERTIFICATE OF SERVICE

I certify that I served a true and correct copy of PacifiCorp’s Reply Testimony filed on August 22, 2017, on the parties listed below via electronic mail and/or or overnight delivery in compliance with OAR 860-001-0180.

Service List UM 1802

COALITION UM 1802 KEVIN HIGGINS (C) ENERGY STRATEGIES LLC 215 STATE ST - STE 200 SALT LAKE CITY UT 84111-2322 [email protected]

JOHN LOWE RENEWABLE ENERGY COALITION 12050 SW TREMONT ST PORTLAND, OR 97225-5430 [email protected]

IRION A SANGER (C) SANGER LAW PC 1117 SE 53RD AVE PORTLAND, OR 97215 [email protected]

CREA GREGORY M. ADAMS RICHARDSON ADAMS, PLLC PO BOX 7218 BOISE, ID 83702 [email protected]

BRIAN SKEAHAN CREA PMB 409 18160 COTTONWOOD RD SUNRIVER, OR 97707 [email protected]

CYRPESS CREEK UM 1802 DAVID BUNGE CYPRESS CREEK RENEWABLES 3250 OCEAN PARK BLVD, STE 355 SANTA MONICA, CA 90405 [email protected]

TODD GLASS WILSON SONSINI GOODRICH & ROSATI PC 701 FIFTH AVE STE 5100 SEATTLE, WA 98104 [email protected]

KEENE M O'CONNOR WILSON SONSINI GOODRICH & ROSATI PC 701 FIFTH AVE STE 5100 SEATTLE, WA 98104 [email protected]

ICNU 1802 JESSE E COWELL (C) DAVISON VAN CLEVE 333 SW TAYLOR ST., SUITE 400 PORTLAND, OR 97204 [email protected]

BRADLEY MULLINS (C) MOUNTAIN WEST ANALYTICS 333 SW TAYLOR STE 400 PORTLAND, OR 97204 [email protected]

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RILEY G PECK DAVISON VAN CLEVE, PC 333 SW TAYLOR, STE 400 PORTLAND OR 97204 [email protected]

IDAHO POWER UM 1802 IDAHO POWER COMPANY PO BOX 70 BOISE, ID 83707-0070 [email protected]

LISA F RACKNER MCDOWELL RACKNER & GIBSON PC 419 SW 11TH AVE., SUITE 400 PORTLAND, OR 97205 [email protected]

DONOVAN E WALKER IDAHO POWER COMPANY PO BOX 70 BOISE, ID 83707-0070 [email protected]

NIPPC UM 1802 ROBERT D KAHN NORTHWEST & INTERMOUTAIN POWER PRODUCERS COALITION PO BOX 504 MERCER ISLAND, WA 98040 [email protected]

SIDNEY VILLANUEVA (C) SANGER LAW, PC 1117 SE 53RD AVE PORTLAND, OR 97215 [email protected]

ODOE UM 1802 DIANE BROAD (C) OREGON DEPARTMENT OF ENERGY 625 MARION ST NE SALEM OR 97301-3737 [email protected]

JESSE D. RATCLIFFE OREGON DEPARTMENT OF ENERGY 1162 COURT ST NE SALEM, OR 97301-4096 [email protected]

WENDY SIMONS OREGON DEPARTMENT OF ENERGY 625 MARION ST NE SALEM, OR 97301 [email protected]

PACIFICORP UM 1802 PACIFICORP, DBA PACIFIC POWER 825 NE MULTNOMAH ST, STE 2000 PORTLAND, OR 97232 [email protected]

ETTA LOCKEY PACIFIC POWER 825 NE MULTNOMAH ST., STE 2000 PORTLAND, OR 97232 [email protected]

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DUSTIN T TILL PACIFIC POWER 825 NE MULTNOMAH ST STE 1800 PORTLAND, OR 97232 [email protected]

PGE UM 1802 ROB MACFARLANE PORTLAND GENERAL ELECTRIC 121 SW SALMON ST, 1WTC0702 PORTLAND, OR 97204 [email protected] [email protected]

V. DENISE SAUNDERS PORTLAND GENERAL ELECTRIC 121 SW SALMON ST 1WTC1301 PORTLAND, OR 97204 [email protected]

RENEWABLE NW RENEWABLE NORTHWEST 421 SW 6TH AVE., STE. 1125 PORTLAND, OR 97204 [email protected]

DINA DUBSON KELLEY (C) RENEWABLE NORTHWEST 421 SW 6TH AVE STE 1125 PORTLAND, OR 97204 [email protected]

SILVIA TANNER (C) RENEWABLE NORTHWEST 421 SW 6TH AVE, STE 1125 PORTLAND, OR 97204 [email protected]

STAFF UM 1802 BRITTANY ANDRUS (C) PUBLIC UTILITY COMMISSION OF OREGON PO BOX 1088 SALEM, OR 97308-1088 [email protected]

STEPHANIE S ANDRUS (C) PUC STAFF--DEPARTMENT OF JUSTICE BUSINESS ACTIVITIES SECTION 1162 COURT ST NE SALEM, OR 97301-4096 [email protected]

NOLAN MOSER (C) OREGON PUBLIC UTILITY COMMISSION PO BOX 1088 SALEM OR 97308 [email protected]

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Dated this 22nd day of August, 2017. __________________________________ Katie Savarin Coordinator, Regulatory Operations

Docket No. UM 1802 Exhibit PAC/400 Witness: Daniel MacNeil

BEFORE THE PUBLIC UTILITY COMMISSION OF OREGON

PACIFICORP

___________________________________________________________

Reply Testimony of Daniel MacNeil

August 2017

PAC/400 MacNeil/i


REPLY TESTIMONY OF DANIEL MACNEIL

TABLE OF CONTENTS

PURPOSE AND SUMMARY OF TESTIMONY .......................................................... 1

REPLY TESTIMONY .................................................................................................... 4

Deferral of Like-for-Like Resources ........................................................................... 4

2021 Wyoming Wind Resources ............................................................................... 10

Market Price Floor ..................................................................................................... 17

QF Queue ................................................................................................................... 20

CONCLUSION ............................................................................................................. 23

ATTACHED EXHIBIT Exhibit PAC/401 – Illustrative comparison of proposed indicative avoided cost pricing

PAC/400 MacNeil/1


Q. Are you the same Daniel MacNeil who previously submitted testimony in this 1

proceeding on behalf of PacifiCorp d/b/a Pacific Power? 2

A. Yes. 3

PURPOSE AND SUMMARY OF TESTIMONY 4

Q. What is the purpose of your reply testimony? 5

A. My reply testimony replies to response testimony filed on August 14, 2017, by Public 6

Utility Commission of Oregon Staff (Staff) witness Ms. Brittany Andrus (Staff/200), 7

Renewable Energy Coalition (Coalition) and the Community Renewable Energy 8

Association (CREA) witnesses Mr. John R. Lowe, Mr. Brian Skeahan, and Mr. Kevin 9

Higgins (REC-CREA/200), and Industrial Customers of Northwest Utilities (ICNU) 10

witness Mr. Bradley G. Mullins (ICNU/200). 11

Q. Please summarize your reply testimony. 12

A. My testimony addresses PacifiCorp’s recommendations that the Commission approve 13

the revised methodology for calculating non-standard non-renewable portfolio 14

standard (RPS) avoided cost prices,1 as set forth in my January 2017 testimony 15

(PAC/100), and modified and clarified in my July 2017 testimony (PAC/300). 16

In summary, PacifiCorp asks the Commission to: 17

Approve the Partial Displacement Differential Revenue Requirement 18 (PDDRR) methodology for calculating non-RPS avoided cost prices. 19 PacifiCorp’s proposed methodology includes the following: 20

Defer like-for-like renewable resources; 21

Eliminate the market price floor for non-standard avoided cost 22 prices; 23

1 Because the distinguishing feature between the two price streams is tied to avoided RPS compliance costs, it is more precise to refer to the two price streams as the “RPS avoided cost price stream” and the “non-RPS avoided cost price stream.” This terminology is consistent with the terminology used in PAC/300.

PAC/400 MacNeil/2


Calculate avoided cost prices based on all the Qualifying Facilities 1 (QFs) that have previously requested indicative pricing and are 2 timely proceeding with negotiations; and 3

QFs which complete negotiations and sign an execution-ready 4 contract may request updated pricing as of the date of execution 5 which incorporates only previously signed contracts. 6

Find that the 2021 Wyoming wind resources included in the 2017 7 Integrated Resource Plan (IRP) preferred portfolio are not deferrable for 8 purposes of avoided cost pricing because of their unique factual 9 circumstances. 10

Open a generic investigation to change the framework for determining 11 avoided cost prices for RPS-eligible QFs. To be clear, PacifiCorp is not 12 asking the Commission to rule on the merits of its recommended 13 framework in this case; rather, the company requests only that the 14 Commission open a generic investigation. 15

Q. Please describe PacifiCorp’s proposal for calculating non-standard non-RPS 16

avoided cost prices. 17

A. PacifiCorp’s proposal refines the PDDRR methodology approved by the Commission 18

in Order No. 16-174.2 The approved PDDRR methodology allows for the deferral of 19

thermal resources identified in the IRP preferred portfolio. The non-RPS avoided 20

cost proposal expands the pool of deferrable resources to include cost-effective 21

renewable resources identified in the preferred portfolio. Due to differences in the 22

operational characteristics of renewable resources of various types, PacifiCorp 23

proposes that QFs be eligible to defer cost-effective renewable resources of the same 24

type. Or, if no renewable resources of the same type remain in the IRP preferred 25

portfolio during the proposed contract term, a QF would partially displace the next 26

major thermal resource in the IRP preferred portfolio, consistent with the existing 27

2 In the Matter of the Public Utility Commission of Oregon Investigation into Qualifying Facility Contracting and Pricing, Docket No. UM 1610, Order No. 16-174 at 23 (May 13, 2016).

PAC/400 MacNeil/3


PDDRR methodology. 1

During periods when a QF is deferring a cost-effective renewable resource, 2

PacifiCorp would retain the renewable energy certificates (RECs) associated with the 3

QF’s output to maintain customer indifference in light of the lost RECs from the 4

deferred resource. During other periods, the QF would retain all RECs associated 5

with its output. Using the same resource type to calculate avoided costs will better 6

ensure that customers remain indifferent to the QF generation by maintaining a risk 7

profile that is comparable to that of the least-cost, least-risk portfolio established in 8

the IRP. My testimony demonstrates that avoided cost pricing based on the deferral 9

of wind resources by solar or baseload resources, as proposed by Staff, the Coalition, 10

and CREA, produces unreasonable results. 11

My testimony further demonstrates the deferral of the 2021 Wyoming wind 12

resources included in the 2017 IRP preferred portfolio is not a reasonable 13

representation of avoided costs for Oregon QFs. The time-sensitive customer benefits 14

provided by the Wyoming wind resources result largely from their eligibility for 15

federal wind production tax credits (PTCs). Accounting for PTCs in the avoided cost 16

prices, however, produces unreasonable results—if the PTCs are levelized over the 17

life of the resource, then customers may be deprived of their full value; or, if the 18

PTCs are included in the first ten years of the avoided cost price stream 19

(corresponding to when they would be received), the avoided cost prices are too low, 20

and sometimes negative. Given the fact-specific limitations on using the Wyoming 21

wind resources for avoided cost pricing, the company recommends that the 22

PAC/400 MacNeil/4


Commission conclude here that they are not deferrable, if the Commission chooses to 1

determine the avoided cost treatment of the resources in this case. 2

Q. Do you have any additional recommendations? 3

A. Yes. PacifiCorp continues to recommend that the Commission open a generic 4

investigation to develop a framework for calculating avoided RPS compliance costs 5

for use in standard and non-standard RPS avoided cost pricing and in other 6

applications as appropriate. The proposal for an RPS avoided cost price stream stems 7

from the recognition that, from a system cost perspective, whether a QF is ceding its 8

RECs to PacifiCorp has no bearing on how the energy and capacity from that 9

resource will displace alternatives. 10

REPLY TESTIMONY 11

Deferral of Like-for-Like Resources 12

Q. Please describe PacifiCorp’s proposal for determining the avoided costs based 13

on deferral of cost-effective renewable resources from the IRP preferred 14

portfolio. 15

A. PacifiCorp proposes that under the non-RPS avoided cost methodology, renewable 16

QFs would defer the next major cost-effective renewable resource of the same type in 17

the IRP preferred portfolio, based on equivalent capacity contributions. In my July 18

2017 testimony, I clarified that the “type” is meant to reflect the operational 19

characteristics of the QF on PacifiCorp’s system, not the specific technology of the 20

resource identified in the preferred portfolio. 21

The 2017 IRP preferred portfolio includes wind, solar, and geothermal 22

resources. The geothermal resource in the 2017 IRP preferred portfolio is expected to 23

have a flat generation profile with little daily or seasonal variation. Biomass, biogas, 24

PAC/400 MacNeil/5


hydro, and other renewable resources with similar output profiles would also be 1

eligible to displace the geothermal resource. Any resource with relatively flat output 2

over a daily and monthly timeframe would be considered a resource of the same type 3

as the geothermal resource in the 2017 IRP. Thus, all the likely types of renewable 4

QF resources correspond to a renewable resource identified in PacifiCorp’s 2017 IRP 5

preferred portfolio. 6

Q. What resources from the 2017 IRP preferred portfolio would be considered 7

deferrable by QFs in Oregon? 8

A. PacifiCorp proposes that QFs in Oregon be eligible to defer the following resources 9

from the 2017 IRP preferred portfolio, with deferral of renewable resources limited to 10

QFs with the same operational characteristics. The commercial operation date and 11

nameplate capacity of each resource is also shown. 12

Thermal: 13

2029: Utah North simple cycle combustion turbine (SCCT) (200 MW) 14

2030: Willamette Valley combined cycle combustion turbine (CCCT) (436 MW) 15

2033: Dave Johnston SCCT (200 MW) 16

2033: Dave Johnston CCCT (477 MW) 17

Wind: 18

2031: Dave Johnston wind (85 MW) 19

2036: Goshen wind (774 MW) 20

Solar: 21

2028-2034: Yakima fixed tilt solar (240 MW) 22

2031-2036: Utah South single tracking solar (800 MW) 23

PAC/400 MacNeil/6


Geothermal: 1

2029: West geothermal (30 MW) 2

Q. Do parties continue to object to PacifiCorp’s proposal to limit deferral of 3

renewable resources to QFs of the same type? 4

A. Yes. In response testimony, parties largely reiterate arguments that were already 5

made and that were already addressed. But there are some new arguments and 6

proposals that I will address here. 7

Q. The Coalition and CREA claim that “non-RPS renewable acquisitions would 8

never be part of the QF’s avoided cost rate.”3 Is this accurate? 9

A. Not at all. As described above, several renewable resources are present in the IRP 10

preferred portfolio and are available for deferral. I also explained at length in my 11

previous testimony how non-RPS renewable acquisitions would be considered when 12

determining a non-RPS avoided cost price.4 13

Q. Can Oregon QFs actually defer the 2028 solar resources from the IRP preferred 14

portfolio identified above? 15

A. No. Since the 2017 IRP was prepared, PacifiCorp has entered contracts with solar 16

QFs totaling over 150 MW of nameplate capacity. After accounting for the deferral 17

associated with those resources as well as a 5 MW solar QF that was included in the 18

2017 IRP but recently terminated, the first deferrable solar resource in the 2017 IRP 19

preferred portfolio is now in 2031. This highlights the importance of the potential QF 20

queue and consideration of the aggregate effects of resource acquisitions. 21

3 REC-CREA/200, Lowe-Skeahan/8. 4 See PAC/300, MacNeil/14-25.

PAC/400 MacNeil/7


Q. Has Staff modified its recommendation based on PacifiCorp’s proposal? 1

A. Yes. Staff now argues that if the PDDRR methodology cannot adequately reflect 2

avoided costs without using PacifiCorp’s proposed like-for-like methodology, then 3

the Commission should reject the PDDRR methodology and revert back to the 4

previous methodology that used the proxy resource methodology, modified to 5

account for the avoided cost pricing factors set forth in the Federal Energy Regulatory 6

Commission’s (FERC) regulations.5 7

Q. How do you respond to Staff’s recommendation to reject the PDDRR in favor of 8

the prior methodology? 9

A. The Commission has already found that the PDDRR methodology is more accurate 10

than the prior one and Staff has not presented any compelling reason to revert back to 11

a less accurate methodology.6 Contrary to Staff’s assertion, PacifiCorp did not testify 12

that the PDDRR methodology cannot determine an avoided cost for different types of 13

renewable QFs. I testified that PacifiCorp’s proposal to calculate avoided costs based 14

on the deferral of a resource of the same type results in more accurate avoided cost 15

prices, which is the reason the Commission approved the PDDRR methodology in the 16

first place.7 17

Staff’s criticism of the PDDRR methodology also appears to misunderstand 18

the role of the Generation and Regulation Initiative Decision Tools model (GRID) in 19

calculating avoided costs. Staff testifies that PacifiCorp claims that GRID is non-20

5 Staff/200, Andrus/7. 6 Order No. 16-174 at 23 (“We approve PacifiCorp's request to use its PDDRR method going forward. We agree this GRID model-based method more accurately values energy and capacity on PacifiCorp's system by taking into account the unique characteristics (including location, delivery pattern, and capacity contribution) of each QF.”). 7 Order No. 16-174 at 23 (“We are persuaded that the PDDRR method improves non-standard QF avoided cost pricing for QFs selling to PaciCorp and we adopt it.”).

PAC/400 MacNeil/8


adaptable to determining avoided costs when a QF is assumed to defer a different 1

type of resource. The PDDRR methodology relies on GRID to model the avoided 2

cost of energy, not the avoided cost of capacity or the composition of a least-cost, 3

least-risk resource portfolio. PacifiCorp’s position is that the GRID model, when 4

properly applied, produces a reasonable estimate of avoided energy costs. It is 5

necessary, however, to calculate the avoided cost of capacity by deferring like-for-6

like resources because doing so maintains a reasonable balance of cost and risk that is 7

consistent with the IRP preferred portfolio. As my July 2017 testimony indicated, if a 8

solar QF, for example, is deemed to defer a wind resource, the cost and risk profile of 9

the company’s resource portfolio will be altered in a way that cannot be reasonably 10

reflected in the avoided cost price. 11

Moreover, current standard renewable avoided cost prices have an implied 12

RPS compliance avoided cost of $33.16 per MWh, which is patently unreasonable 13

when PacifiCorp has three different types of cost-effective renewable resources in its 14

2017 IRP preferred portfolio. These renewable resources provide capacity and 15

energy at a cost that is less than the available non-renewable alternatives without even 16

considering the RPS compliance value associated with their RECs. Reverting to a 17

methodology that is based on such an inflated avoided RPS compliance cost will not 18

produce a reasonable avoided cost price, even after the standard price is adjusted to 19

account for FERC’s factors. 20

PAC/400 MacNeil/9


Q. The Coalition and CREA recommend that the Commission not address 1

PacifiCorp’s proposal to calculate avoided costs by deferring a like resource 2

here, and instead, address it in a generic proceeding.8 Is this a reasonable 3

recommendation? 4

A. No. PacifiCorp’s proposal is unique to PacifiCorp. Only one other utility—Portland 5

General Electric Company (PGE)—currently offers multiple price streams and PGE 6

does not use a methodology similar to the PDDRR methodology to calculate those 7

price streams.9 The Commission has found that each utility can calculate its non-8

standard avoided costs in a different manner and this docket is specifically intended 9

to address PacifiCorp’s methodology for calculating its non-standard avoided cost 10

pricing for renewable resources. PacifiCorp’s proposal is best resolved in a utility-11

specific investigation. 12

Q. The Coalition and CREA also argue that the Commission previously rejected 13

PacifiCorp’s proposal to allow only deferral of a similar type of resource.10 Do 14

you agree with their understanding of Commission precedent? 15

A. No. The Coalition and CREA point out that in Order No. 11-505 the Commission 16

declined to approve a different avoided cost price for each type of renewable 17

resource, implying that PacifiCorp’s proposal here was already disposed of in docket 18

UM 1396.11 But in Order No. 14-058, the Commission adopted adjustments to 19

standard fixed avoided costs based on the specific operational characteristics of 20

different types of renewable resources. The current standard avoided cost pricing 21

8 REC-CREA/200, Lowe-Skeahan/6. 9 See Order No. 16-174 at 22 (describing PGE’s methodology for calculating non-standard avoided cost prices). 10 REC-CREA/200, Lowe-Skeahan/12. 11 REC-CREA/200, Lowe-Skeahan/12.

PAC/400 MacNeil/10


includes rates specific to baseload, wind, tracking solar, and fixed solar resources. 1

PacifiCorp’s proposal takes into consideration additional resource-specific 2

characteristics that are currently ignored for the purposes of simplicity in standard 3

avoided cost pricing. 4

Q. The Coalition and CREA suggest that a renewable QF should have the option to 5

compare the pricing results from the available options prior to selecting its 6

preferred pricing stream.12 How do you respond? 7

A. The non-RPS avoided cost pricing methodology proposed in my July testimony 8

withdrew the proposal that QFs have the option to select the resources they wish to 9

defer. Instead, like renewable resources are deferred, or if none remain in the 10

preferred portfolio during the QFs term, non-renewable resources are deferred. This 11

recognizes that whether a QF retains the RECs it produces and how it chooses to be 12

compensated have no bearing on how the energy and capacity from that resource will 13

displace alternatives. QFs would have the option to provide additional RECs to 14

support PacifiCorp’s RPS compliance obligations, but PacifiCorp is proposing that 15

the specifics of this option be addressed in a generic proceeding. 16

2021 Wyoming Wind Resources 17

Q. Staff recommends that the treatment of the 2021 Wyoming wind resources in the 18

2017 IRP is beyond the scope of the issues for this case and should be instead 19

addressed in a post-IRP acknowledgement avoided cost filing.13 How do you 20

respond to this recommendation? 21

A. PacifiCorp disagrees that the treatment of 2021 Wyoming wind resources is beyond 22

12 REC-CREA/300, Higgins/3. 13 Staff/200, Andrus/9.

PAC/400 MacNeil/11


the scope of this case because the PDDRR methodology approved by the Commission 1

in docket UM 1610 does not use the most recent acknowledged IRP to calculate 2

avoided costs. Instead, to produce an avoided cost forecast based on the most up-to-3

date information, the PDDRR methodology relies on the most recently filed IRP.14 4

PacifiCorp explained in docket UM 1610 exactly how the PDDRR methodology 5

relies on the most recent IRP, or IRP update, to calculate avoided cost prices: 6

An accurate determination of non-standard avoided cost prices 7 requires a more involved calculation than the Proxy Method, 8 and merits the use of updated inputs. In order for retail 9 customers to be indifferent to the calculated avoided cost 10 prices, the underlying assumptions and modeling inputs must 11 be based on the best information available at the time the QF 12 pricing is prepared. Accordingly, all modeling inputs in the 13 PDDRR method should be subject to update, including but not 14 limited to the forecast of wholesale market prices for electricity 15 and natural gas, executed purchase and sale contracts, wheeling 16 contracts, coal contracts, and the retail load forecast. The 17 resource additions outlined in the IRP preferred portfolio 18 should be updated with a new IRP or IRP update, or if there is 19 a known change to the IRP action plan, such as a delay or 20 abandonment of a resource addition that causes a change to 21 the preferred portfolio.15 22

When the Commission approved the PDDRR methodology, it did not modify this 23

aspect of the methodology. Commission action in this docket does not require an 24

outcome in the 2017 IRP nor does it presume or prescribe an outcome in the 2017 25

request for proposals (RFP). 26

14 See, e.g., Docket No. UM 1610, PAC/800, Dickman/18 (“the PDDRR method includes avoided fixed costs of the Company’s next major resource acquisition, based on the cost and timing of the next deferrable resource in the IRP preferred portfolio . . . The timing for including avoided fixed costs from the next deferrable resource is adjusted to account for new QFs (since the IRP was published) that will be on the Company’s system at the time the next major resource is acquired.”); id at 21-22 (“The calculation of the avoided energy cost begins with existing and planned resources that represent the Company’s most recent IRP resource portfolio.”); id. at 23 (“The Company calculates the avoided fixed costs of the next deferrable resource outside of the GRID model based on partial displacement of the next major thermal resource acquisition in the IRP (that has not already been displaced by QFs with contracts extending beyond the expected online date of the next major resource).”). 15 Docket No. UM 1610, PAC/800, Dickman/26 (emphasis added).

PAC/400 MacNeil/12


If, however, the Commission ultimately does not acknowledge the 2017 IRP, 1

or makes any specific findings related to the Wyoming wind resources in either the 2

2017 IRP or RFP docket, PacifiCorp will modify its treatment of the resources in its 3

avoided cost calculations as required by the Commission. 4

Q. The Coalition and CREA recommend that the Commission determine here that 5

the 2021 Wyoming wind resources are deferrable and can form the basis for 6

Oregon avoided cost prices.16 How do you respond? 7

A. PacifiCorp disagrees that the Wyoming wind resources are deferrable, for the reasons 8

set forth in my July testimony. If the Wyoming wind resources are considered 9

deferrable, however, the avoided cost prices must reasonably account for the value of 10

PTCs by recognizing their value in the avoided cost price in the first ten years, when 11

the PTCs are actually received. 12

The figure below illustrates the avoided cost prices for several different 13

resource types based on the deferral of the Wyoming wind resources, and assuming 14

that the value of the PTC is not levelized. 15

16 REC-CREA/200, Higgins/2-3.

PAC/400 MacNeil/13


Figure 1: Avoided Cost Assuming Deferral of IRP Wind Resources without Levelized PTCs, by Resource Type, with Existing Resource Capacity Position

As the figure shows, if the Wyoming wind resources are considered deferrable 1

for purposes of PacifiCorp’s avoided costs, the avoided cost prices are significantly 2

lower than they would be otherwise because of the impact of the PTCs. In fact, for a 3

solar QF, the avoided cost price is primarily negative until 2031 when the PTC for the 4

Wyoming wind resource has expired. 5

Q. What is the basis for including the PTCs in the first 10 years of the avoided cost 6

calculation, rather than levelizing the tax credits over the life of the resource? 7

A. As PacifiCorp has described, the new Wyoming wind resources will receive the full 8

value of the PTCs only if they are on line by the end of 2020. Thus, these wind 9

(4,000)

(3,000)

(2,000)

(1,000)

‐

1,000

2,000

3,000

4,000

‐$200

‐$150

‐$100

‐$50

$0

$50

$100

$150

$200

2018 2020 2022 2024 2026 2028 2030 2032 2034 2036

2017 IR

P Existing Resource Summer Capacity

Position Including Available FOTs (MW)

Avoided Cost Price ($/M

Wh)

Summer Capacity Surplus Summer Capacity Shortfall

OR Solar vs 2021 Wind PTC adj. OR Biomass vs 2021 Wind PTC adj.

OR Wind vs 2021 Wind PTC adj. 2017 IRP OR Solar Cost

PAC/400 MacNeil/14


resources cannot be deferred, because a deferral eliminates the PTC benefits and 1

makes the projects non-economic. 2

Moreover, because the PTCs will be received in the first 10 years of 3

operations, it is reasonable to model the same treatment in the avoided cost 4

calculation. If the value of the PTCs is spread out over the life of the resources for 5

purposes of avoided cost calculations, it is comparable to providing the QF a 6

levelized avoided cost payment, which the Commission has consistently declined to 7

do.17 To make customers truly indifferent as between the new Wyoming wind 8

resources or an Oregon QF, the PTCs must be accounted for in this way. 9

Q. Why are the avoided cost prices in Figure 1 above different from the avoided 10

cost prices included in your July testimony that were also based on the deferral 11

of the 2021 Wyoming wind resources?18 12

A. In my July testimony, I modeled avoided cost pricing assuming that the value of 13

PTCs was levelized over the life of the asset, which is thirty years in the case of the 14

2021 Wyoming wind resources. With levelized PTCs, if a QF is assumed to defer the 15

2021 Wyoming wind resources and has a contract term of fifteen years, retail 16

customers would lose at least half of the assumed benefits of the PTCs. The purpose 17

of the modeling in my July testimony was to demonstrate the impact of allowing any 18

type of renewable QF to defer the wind resources, and was not focused on how to 19

appropriately model the impact of PTCs on the avoided cost price, which is why, for 20

simplicity, my July testimony used levelized PTCs. 21

17 See Order No. 14-058 at 32. 18 See PAC/300, MacNeil/22 (Figure 1).

PAC/400 MacNeil/15


Q. The Coalition and CREA claim that PacifiCorp has indicated that it will pursue 1

the 2021 Wyoming wind resources regardless of whether there are other 2

available supplies, like an Oregon QF.19 Is this true? 3

A. No. First, PacifiCorp explained that unlike the remaining resources in its preferred 4

portfolio, the 2021 Wyoming wind resources cannot be deferred because any delay 5

will compromise their PTC-eligibility and render them uneconomic to meet 6

PacifiCorp’s resource needs. Second, PacifiCorp explained that it cannot partially 7

defer or avoid the Wyoming wind resources because their economic benefits correlate 8

to their size. Thus, a 10 MW Oregon QF will not reduce the size of the Wyoming 9

wind resource by a capacity equivalent amount. PacifiCorp never claimed that it is 10

pursuing these resources at any cost or irrespective of market or resource 11

developments. Indeed, PacifiCorp has made clear that pursuit of the Wyoming wind 12

resources is not a zero-sum opportunity: if other opportunities exist for least-cost, 13

least-risk resources to meet PacifiCorp’s resource needs, it is a matter of “and” not 14

“or”. 15

Q. Is there any additional evidence that the proposed wind and transmission 16

resources are not deferrable by QF resources elsewhere on PacifiCorp’s system? 17

A. Yes. I noted in my July testimony that the capacity contribution associated with the 18

new wind resources amounted to 174 MW. Since the 2017 IRP was prepared, 19

PacifiCorp has executed QF contracts for resources outside of the constrained area of 20

Wyoming with a capacity contribution totaling over 90 MW. On a capacity 21

equivalent basis, this represents approximately over half of the 2021 Wyoming wind 22

19 REC-CREA/200, Higgins/7.

PAC/400 MacNeil/16


resource, or over 500 MW nameplate capacity. Yet these acquisitions have had no 1

impact on PacifiCorp’s plans to pursue the 2021 Wyoming wind resources because 2

even with the additional QFs, the wind and transmission resources remain cost-3

effective. 4

Q. ICNU cautions against setting avoided cost prices based on the 2021 Wyoming 5

wind resources because they may never be built if PacifiCorp does not receive 6

the regulatory approvals it requires.20 Do you agree? 7

A. I agree that the 2021 Wyoming wind resources should not be used to establish 8

avoided cost prices for the reasons set forth above and in my previous testimony. I 9

disagree with ICNU’s argument that the Wyoming wind resources should be 10

excluded from the avoided cost calculation because they may never be built. That 11

same reasoning could apply to any resource in PacifiCorp’s preferred portfolio—i.e., 12

PacifiCorp may not ultimately build any resource if PacifiCorp does not obtain the 13

necessary regulatory approvals. Yet, for avoided costs we must assume that the 14

resources in the preferred portfolio will be acquired because that is a fundamental 15

assumption underlying the notion that a QF will allow the deferral of another 16

resource. If we assume that no resources will be built, then no resources can be 17

deferred. And, while ICNU is not clear about what regulatory approvals are required, 18

the only regulatory approval that is necessary to construct the wind resources is the 19

granting of a certificate of public convenience and necessity from the Wyoming 20

Public Service Commission. 21

20 ICNU/200, Mullins/4.

PAC/400 MacNeil/17


Furthermore, if updated analysis incorporating the RFP results does not 1

indicate the new wind and transmission resources are part of the least-cost, least-risk 2

portfolio, PacifiCorp will stop its pursuit of this opportunity without requiring 3

regulatory action. 4

Market Price Floor 5

Q. Staff argues that PacifiCorp’s July 2017 testimony demonstrated that the 6

market price floor is appropriate until an individual QF causes a constraint that 7

limits access to market.21 How do you respond? 8

A. PacifiCorp has demonstrated that the imposition of the market price floor produces 9

payments to QFs that exceed the company’s avoided costs because of transmission 10

constraints existing today. Indeed, Staff appears to acknowledge that current 11

transmission constraints mean that the market price floor increases QF payments 12

above PacifiCorp’s avoided costs. But Staff reasons that because the market price 13

floor only exceeds avoided costs by eight percent, it remains reasonable.22 PacifiCorp 14

disagrees and recommends that the Commission eliminate the market price floor in 15

this case. 16

If the Commission declines to eliminate the market price floor in this case, 17

however, consistent with Staff’s recommendation, the company will make a filing 18

with the Commission when a specific QF will experience a transmission constraint 19

that merits elimination of the market price floor. 20

21 Staff/200, Andrus/12. 22 Staff/200, Andrus/12.

PAC/400 MacNeil/18


Q. Staff claims that market dynamics, such as market depth and volatility, are 1

included in PacifiCorp’s forward price curve and that this means that the 2

forward price curve is an appropriate measure of PacifiCorp’s avoided costs.23 3

How do you respond? 4

A. The Commission has previously found that PacifiCorp’s forward price curve on its 5

own does not adequately capture market depth and volatility.24 The forward price 6

curve itself is a point forecast, reflecting current market conditions in the near term, 7

and a single fundamentals-based forecast in the long term. Significant changes in 8

PacifiCorp’s resource mix, such as the acquisition of appreciable volumes of QFs are 9

not reflected in the forecast. In light of the limitations of the forward price curve, 10

PacifiCorp proposed and the Commission applies limits to market sales within the 11

GRID model. Overriding these limits via the market price floor effectively assumes 12

unlimited market depth. 13

The Commission has also approved adjustments to account for the market 14

effects of historical day-ahead and real-time transactions within the GRID model, 15

though those have not been employed for avoided cost purposes.25 As currently 16

formulated, the methodology results in incremental day-ahead and real-time 17

transaction costs that are identical to an historical average, regardless of the system 18

composition. While PacifiCorp has recently quantified day-ahead and real-time 19

transactions benefits associated with dispatchable resources, it has not quantified the 20

23 Staff/200, Andrus/12-13. 24 See, e.g., In the Matter of PacifiCorp dba Pacific Power 2013 Transition Adjustment Mechanism, Docket No. UE 245, Order No. 12-409 (Oct. 29, 2012) (addressing the use of market caps in GRID to account for the fact the forward price curve does not account for market liquidity). 25 See In the Matter of PacifiCorp dba Pacific Power 2016 Transition Adjustment Mechanism, Docket No. UE 296, Order No. 15-394 (Dec. 11, 2015).

PAC/400 MacNeil/19


effect for QFs. In particular, wind and solar QFs are expected to contribute to higher 1

day-ahead and real-time costs. For instance, new wind resources are most likely to 2

generate when regional wind resources are also producing. Market prices are likely 3

to be depressed when significant quantities of wind resources are available. 4

Q. Staff argues that if PacifiCorp’s market price forecast is higher than its avoided 5

cost prices, then it is up to PacifiCorp to modify its forward price curve.26 How 6

do you respond? 7

A. Staff’s argument misses the mark because the problem is not with the forward price 8

curve itself, it is with using the forward price curve, and only the forward price curve, 9

to calculate avoided cost prices. I testified that forward prices are not indicative of 10

avoided costs because PacifiCorp is required to hold reserves for QFs and the costs of 11

those reserves is not included in the forward price curve. Staff does not dispute this 12

fact, and instead, appears to argue that PacifiCorp should modify its forward price 13

curve to build in the cost of contingency reserves, which is a proposal that is 14

completely without merit. 15

I also testified that PacifiCorp’s transmission limitations can preclude it from 16

selling QF output at market, which is a fundamental assumption underlying the use of 17

a market price as an avoided cost. Transmission constraints, however, are not built 18

into the company’s forward price curve, and it would make little sense to forecast 19

market prices based on the PacifiCorp’s expected transmission constraints. 20

My testimony demonstrated that there are many circumstances and costs that 21

are not included in the forward price curve that make the forward price curve an 22

26 Staff/200, Andrus/13-14.

PAC/400 MacNeil/20


unreasonable proxy avoided cost price. There is no basis for Staff to claim that 1

PacifiCorp should simply modify its forward price curve to make it a more reasonable 2

proxy for an avoided cost price. Furthermore, the intent of the PDDRR methodology 3

and calculation of avoided energy costs within the GRID model is to capture each of 4

the adjustments described above, and to do so while accounting for both the 5

individual and aggregate effects of the resources on PacifiCorp’s system. 6

QF Queue 7

Q. Is the QF queue alternative provided by PacifiCorp more restrictive than that 8

proposed by the Coalition and CREA? 9

A. Yes. PacifiCorp already has an obligation to purchase all QF output on behalf of its 10

customers, and the right under PURPA to pay no more than the cost it would 11

otherwise have incurred. Under no circumstance should be PacifiCorp be forced to 12

offer multiple QFs prices based on the same increment of avoided capacity or avoided 13

energy. The Coalition’s and CREA’s proposal combines the price certainty (within 14

certain limits, price updates are at a QF’s request) of PacifiCorp’s potential QF queue 15

methodology and avoided cost pricing based on the first increment of capacity and 16

energy from the signed QF queue methodology. This defeats the purpose of both 17

methodologies. PacifiCorp’s proposal offers a shortcut for QFs that are unwilling to 18

wait until they naturally reach the front of the potential QF queue, but reasonably 19

requires the QF to demonstrate their ability to move forward by completing all 20

negotiations besides price before taking that shortcut. 21

PAC/400 MacNeil/21


Conclusion 1

Q. Do you have any further comments regarding the determination of accurate 2

non-RPS avoided costs in this docket? 3

A. Yes. I would like to note that, while parties have now provided two rounds of 4

testimony, their proposals have been general and have not quantified the impact of 5

their recommendations, even though, through discovery, PacifiCorp provided 6

indicative pricing based on the parties’ preferred assumptions. Without quantifying 7

the impact of a particular proposal, it can be difficult to ascertain whether customers 8

would be indifferent to QF generation. 9

The table below identifies each of the proposals that have been made in this 10

case, and exhibit PAC/401, to my testimony provides indicative pricing for solar, 11

wind, and biomass resources based on each of the proposals. 12

Table 1: Proposed Avoided Cost Methodologies First Proxy Resource

Methodology Solar Wind Biomass

PDDRR ‐ Like for Like 2028 Solar 2031 Wind 2029 Geothermal

PDDRR ‐ Any Renewable 2021 WY Wind 2021 WY Wind 2021 WY Wind

Standard Renewable 2028 WY Wind (2015 IRP)

2028 WY Wind (2015 IRP)

2028 WY Wind (2015 IRP)

PAC/400 MacNeil/22


Table 2: Sample QF REC Obligations to PacifiCorp, per MWh of QF output

Methodology Start Year

IRP Resource Solar Wind Biomass

PDDRR ‐ Like for Like (first in queue) Varies Like 2028: 0.3;2029: 0.6

2031: 0.8 2029: 0.9

PDDRR ‐ Like for Like (later in queue) Varies Like 2033: 0 (SCCT)

2031: 0.3; 2036: 0.8

2033: 0 (SCCT)

PDDRR ‐ Any Renewable 2021 WY Wind 6.1 0.8 2.7

Standard Renewable 2028 WY Wind (2015 IRP)

1.0 1.0 1.0

Q. Are the differences in REC output between QFs and deferred resources in Table 1

2 significant? 2

A. Yes. As I described in my July testimony, under the current standard renewable 3

avoided cost pricing a QF receives $33.16 for each REC that is transferred to 4

PacifiCorp. At this price, the RECs delivered between 2028 and 2035 by the 1,100 5

MW of 2021 Wyoming wind resources identified in the IRP preferred portfolio would 6

be worth approximately $1 billion. This time period corresponds to the current 7

renewable deficiency period and the end of the 15-year fixed price term of a QF 8

contract. Yet, the 2017 IRP analysis indicates that the 2021 Wyoming wind resources 9

are part of the least-cost, least-risk portfolio despite assuming a zero avoided RPS 10

compliance cost. 11

As shown in Table 2, each REC produced by a solar QF deferring the 2021 12

Wyoming wind resource would result in a loss of six RECs. If the 2021 Wyoming 13

wind resource is fully deferred by solar resources based on equivalent capacity 14

contributions, the net loss of RECs would represent an incremental RPS compliance 15

cost of over $800 million based on the cost of RECs implied by the current standard 16

renewable avoided costs. Or the incremental RPS compliance cost associated with 17

PAC/400 MacNeil/23


these lost RECs could be zero, based on the fact that the fact that the 2021 Wyoming 1

wind resources are part of the least-cost, least-risk portfolio and less expensive than 2

non-renewable alternatives. In light of the appreciable difference in these outcomes it 3

is appropriate to maintain the same level of RPS compliance obligations when a QF 4

defers a renewable resource, an outcome that is supported by limiting deferral to 5

renewable resources of the same type. 6

CONCLUSION 7

Q. Please summarize the recommendations in your reply testimony. 8

A. My reply testimony supports PacifiCorp’s recommendations asking the Commission 9

to approve the PDDRR methodology for calculating non-RPS avoided cost prices as 10

described in my reply testimony, and to find that the 2021 Wyoming wind resources 11

included in the 2017 IRP preferred portfolio are not deferrable for purposes of 12

avoided cost pricing because of their unique factual circumstances. In addition, 13

PacifiCorp asks the Commission to open a generic investigation to change the 14

framework for determining avoided cost prices for RPS-eligible QFs. 15

Q. Does this conclude your reply testimony? 16

A. Yes. 17

Docket No. UM 1802 Exhibit PAC/401 Witness: Daniel MacNeil

BEFORE THE PUBLIC UTILITY COMMISSION OF OREGON

PACIFICORP

___________________________________________________________

Exhibit Accompanying Reply Testimony of Daniel MacNeil

Illustrative Comparison of Proposed Indicative Avoided Cost Pricing

August 2017

‐$200

‐$150

‐$100

‐$50

$0

$50

$100

$150

$200

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

Solar Avoided Cost Pricing ($/M

Wh)

PAC Proposed: P

DDRR ‐ Like for Like

PDDRR ‐ 2021 W

ind: N

on‐levelized PTC

PDDRR ‐ 2021 W

ind: Levelized

PTC

Market Price Floor

2017 IR

P Oregon Solar Cost

Standard Renewable 2028

Exhibit PAC/401 MacNeil/1

$0

$20

$40

$60

$80

$100

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

Wind Avoided Cost Pricing ($/M

Wh)

PAC Proposed: PDDRR ‐ Like for Like

PDDRR ‐ 2021 W

ind: N

on‐levelized

PTC

PDDRR ‐ 2021 W

ind: Levelized

PTC

Market Price Floor

Standard Ren

ewable 2028


‐$50

$0

$50

$100

$150

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

Biomass Avoided Cost Pricing ($/M

Wh)

PAC Proposed: PDDRR ‐ Like for Like

PDDRR ‐ 2021 W

ind: N

on‐levelized

PTC

PDDRR ‐ 2021 W

ind: Levelized

PTC

Market Price Floor

Standard Ren

ewable 2028


via electronic filing and huddle · page 2 of 4 riley g peck davison van cleve, pc 333 sw taylor,...

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